transcript for transalta 2016 third quarter results · ©transalta corporation 2016 2 on today’s...

TransAlta Corporation

Third Quarter 2016 Results Conference Call &

Webcast Transcript

Date: Friday, November 4, 2016

Time: 9:00 AM MT/11:00 AM ET

Speakers: Dawn Farrell

President & Chief Executive Officer

Donald Tremblay

Chief Financial Officer

John Kousinioris

Chief Legal and Compliance Officer

Todd Stack

Managing Director and Treasurer

Jaeson Jaman

Manager, Investor Relations

©TransAlta Corporation 2016

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OPERATOR:

Welcome to the TransAlta Corporation 2016 Third Quarter Results Conference Call and Webcast. As a

reminder, all participants are in listen-only mode and the conference is being recorded. After the

presentation, there will be an opportunity to ask questions. To join the question queue, simply press

star, then one on your touchtone phone. Should anyone need assistance during the conference call,

they may signal an Operator by pressing star, and zero on their telephone.

At this time, I would like to turn the conference over to Jaeson Jaman, Manager, Investor Relations.

Please go ahead, Mr. Jaman.

JAESON JAMAN:

Thank you, Zubin. Good morning, and welcome to the TransAlta third quarter 2016 conference call.

With me today are Dawn Farrell, President and Chief Executive Officer, Donald Tremblay, Chief

Financial Officer, John Kousinioris, Chief Legal and Compliance Officer, and Todd Stack, Managing

Director and Treasurer.

The call today is webcast and I invite those listening on the phone to view the supporting slides which

are available on our website. A replay of the call will be available later today and the transcript will be

posted to our website shortly thereafter.

All information provided during this conference call is subject to the forward-looking statement

qualification which is set out in the slide deck and detailed in our MD&A and incorporated in full for the

purposes of today’s call.

The amounts referenced are in Canadian currency, unless otherwise stated.

The non-IFRS terminology used, including comparable gross margin, comparable EBITDA, comparable

funds from operations, comparable free cash flow, and comparable earnings, are reconciled in the

MD&A.


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On today’s call, Dawn and Donald will review the third quarter results and progress made against

TransAlta’s goals and priorities for 2016. After these prepared remarks, we will open the call for

questions.

I’ll now turn the call over to Dawn.

DAWN FARRELL:

Thanks, Jaeson, and welcome to everyone whose joined our call today. It’s November here at

TransAlta, so that usually means I’m going to lose my voice in about the next hour-and-a-half, so I

apologize if I’m a bit hard to understand, and we do have backup in the room.

So, lots to update you on today. Today, I am going to provide you some thoughts on our quarter and

my takeaway from some of the things that are happening here in Alberta and in Canada, and I’m also

going to talk about the progress that we’re making as we meet our 2016 goals. Now, just to remind

you, our 2016 goals were to achieve our operational, financial and safety targets, and I think we’re

doing a great job there; to reposition our capital structure; to grow our portfolio of contracted gas and

renewable assets; and then, finally, to secure a mutually beneficial coal transition arrangement here in

Alberta. So, I’m going to address the first three goals at the beginning of our discussion here today and

then I’ll address the fourth goal in my closing remarks.

So, let me start with an overview on our quarter and year-to-date results, and my analysis on how the

business is progressing in this environment.

When you look at Slide 5, which is on the screen now, you can see that we’ve surpassed the 2015

results for the quarter and year to date for our financial metrics, which include EBITDA, FFO and free

cash flow. The improved results during the quarter and year to date are the result of positive

contributions from the renewable assets that we acquired in the second half of 2015, solid performance

from our gas and renewables portfolio, and cost-reduction initiatives across the fleet that we

implemented in 2015. The last metric, Adjusted Availability, measures operational performance across

our fleet, and was particularly important in our Alberta coal fleet for units that are under long-term PPA

contracts. Thus far in 2016, our Adjusted Availability is up 89.3%, which is also an improvement over

2015.


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So, for me, all of these metrics together clearly demonstrate that we’re continuing to build our execution

advantage here at TransAlta, which was one of our strategic themes that we introduced at our AGM

earlier this year. The other two themes were “balance wins” and “history repeats” and more to come on

those as we get to the end of our conference call today.

We now have Slide 6 on the screen and you can see that—on the past couple of calls, we’ve talked

about this notion of free EBITDA performance and the contribution from our renewables and gas-fired

fleet. This is important, because I want you to see how our performance is increasingly less impacted

by the returns from our coal fleet. As our Chairman noted at our AGM, our transition to becoming a

clean energy company is well underway. Slide 6 shows that our free EBITDA for the year is $608

million, and here you can see that renewables and gas-fired assets account for roughly $450 million, or

68%, of our free EBITDA. You can also see that our free EBITDA for renewables and gas-fired assets

on a year-over-year basis and that’s increased from $347 million last year to $415 million this year,

which is a 20% improvement.

So, let me briefly return to our goals.

We told you we would reposition our capital structure by completing between $400 million to $600

million of project level financing. Now, we didn’t close any project level financing during the quarter,

and you know that we did complete $155 million in the first quarter of this year, which has contributed to

our very strong liquidity position that you can see in our results. As Donald mentioned last quarter, the

demand for project financing remains very strong and we continue to have a very solid set of potential

qualifying assets. I can tell you that I’m very confident, based on the work that our team is doing, that

we’ll meet our goal this year of closing $400 million to $600 million of project financings for 2016.

Now, as many of you know, in the near term, our key project, regarding growth in our portfolio for our

contracted gas and renewable assets, is the completion and the commissioning of the South Hedland

combined cycle project. The South Hedland project continues along at a pace that we’ll have it

operational in mid-2017, and it’s set to deliver against the financial and operational targets that we’ve

set for it.


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We’ve also been working this year on a number of contract extensions for gas assets. I believe that

we’ll be successful here, and you should hear more about this on upcoming calls, and also you know

that we successfully extended our contract with our Akolkolex facility with BC Hydro for 30 years.

We do continue to assess acquisitions and are building a good portfolio of greenfield projects here in

Alberta, Saskatchewan, and other parts of Canada, and also in Australia, and we’ll inform you of those

projects once we meet both our investment hurdles and they become more certain.

So, after Donald’s comments, I’m going to close with some comments on our fourth goal, and with that,

I’ll turn the call over to Donald for his comments on the quarter’s performance and our progress in

meeting our other goals.

DONALD TREMBLAY:

Thank you, Dawn. As Dawn mentioned in her opening remarks, we had another solid quarter both

financially and operationally, all of the businesses delivered better or similar results to last year, our

liquidity position continued to improve, the construction of South Hedland is on track and we are

advancing our project financing initiative.

Slide 8 provides the segmented operational results for the third quarter and year to date. For the year,

our total EBITDA is up 14% to $94 million, mostly due to significant improvement in Canadian coal,

wind and solar, and energy marketing.

Taking a moment to highlight some of the business segment performance for the quarter, you can see

that Canadian coal EBITDA came in at $99 million, $2 million lower than last year. Cost reduction and

efficiency initiatives were offset by higher standard cost for coal resulting from heavy rains and

unplanned outage at the mine. These conditions negatively impacted our coal production and coal

quality in Q3. The impact of this event has carried into the early part of the fourth quarter, but our

mining operation group has developed a plan to recover a large part of the shortfall in production within

the fourth quarter. Canadian coal availability was in line with prior year at 85% in the quarter, as

compared to 86% in the same period in 2015.


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Wind and solar provided $9 million of additional EBITDA during the quarter. This was due, in large part,

to a $5 million contribution from assets we acquired in the second half of 2015. The wind resources in

eastern Canada were also better than the prior year, partially offsetting low price for wind in Alberta.

The power price in Alberta settled at an average of $18 for the quarter, compared to $26 per megawatt

hour in the third quarter of last year. Year-to-date prices have averaged $17 per megawatt hour,

compared to $37 per megawatt hour in 2015. Price did pick up slightly in September and October, as a

result of higher level of planned and unplanned outages in the province. However, we do not expect

this price level to be sustainable. Our view is that when units return to service, price will return to the

lower level that we witnessed earlier this year, as the market remains oversupplied and PPA buyers are

now bidding to maximize the value of their portfolio.

Consistent with prior quarters, our hedging program continued to effectively mitigate the impact of low

price on Canadian coal, allowing us to achieve price in the range of $50 to $55 per megawatt hour this

quarter on our uncontracted generation. Gas and hydro were not impacted materially by lower price

and performed as expected, given they are largely contracted. Even better, our hydro assets in Alberta

generated additional margins during the quarter, with the team actively managing our storage and

taking advantage of the optionality of these assets.

Slide 9 is an overview of our liquidity we have maintained since December 31, 2014. The average

liquidity during this period was $1.3 billion. Throughout the year, we have maintained our liquidity at

$1.5 billion, and at the end of the quarter our liquidity stands at $1.7 billion. We anticipate a high level

of liquidity to be available at year end, as we expect to complete project financing using some of our

contracted assets. This increased flexibility will be of paramount importance as we enter a significant

transitory period for the Company. We also need to complete construction of South Hedland and repay

US$400 million of debt that is maturing in the second quarter of 2017. As demonstrated at the bottom

of the slide, we have consistently moved the mark on adjusted FFO to adjusted net debt. Our goal is to

be at 20% FFO to debt in 2018, when South Hedland is on line and contributing financially for a full

year.

As for 2016 guidance, we are tracking to be well within the range we communicated for EBITDA.

However, we believe our comparable FFO is likely to be at the lower end of the $750 million to $835


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million range, as we expect our financing costs to be slightly higher. FFO also excludes change in

unrealized mark-to-market gains that are included our EBITDA.

Finally, our sustaining capital will be lower than our guidance, as we defer the rehabilitation of our water

diversion project out to 2019, when the power price will support the investment. We also have deferred

some capital at our Sarnia generating station to 2017, as the plant is not running as much as

anticipated due to the low price environment in Ontario. Some of the reduction is also due to

improvement in our capital efficiency and making sure we invest wisely in our portfolio. These actions

will all contribute to us achieving our free cash flow target.

Before I hand the call back to Dawn, I just want to note that we are still expecting a decision on the

2013 Keephills 1 force majeure dispute shortly. In Q4 of 2015, we adjusted our provision for the

arbitration to 50%.

I will now hand the call back to Dawn for our closing remarks.

DAWN FARRELL:

Okay. Thanks, Donald. You all know that we’re continuing with our discussions with the provincial

government on compensation for the capital that is stranded under the proposed Climate Leadership

Plan. Now, since we’re working under a confidentiality agreement, there’s nothing further that I can say

on that matter, but I do have some other comments on the general environment that we’re in, and

there’s been a lot of announcements since the last call.

Since we’ve last talked to you, there’s been lots of ongoing announcements about the federal

government’s approach to climate policy. This has included a proposed $50 carbon price in the

provinces by 2022, as well as potential infrastructure investments and support for introducing new

green energy investments. As well, you know, that yesterday there were also announcements about

some issues in the renewables markets here in Alberta.

All of these announcements must now be factored into how we think about future electricity investments

here in Canada. While the conversations around energy are changing frequently, one thing appears to

be clear. Most of the proposed investments and taxes are intended for the longer term, and so we do


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believe that in the short- to medium-term our coal plants will be needed to power the Alberta system

and support our economy. So, given the changing natures of these conversations, we are very much

focused on making sure that we have really built a lot of optionality into our investment planning as we

go forward here in Alberta.

Now, to this end, we are considering several choices to maximize the value of our fleet. We’ve talked

to you about those in earlier quarters, but just to remind you, first of all, we can run the plants that we

have today in the Alberta market on coal until 2030, and then we can convert them to gas to provide

backup peaking to a market that will have more renewables. So, that’s an option. Another option we

have is we can convert the coal plants to gas earlier, at the end of their PPA period, roughly in the 2020

timeframe. We have other options, including expanding our hydro, which are significant, and our wind

operations, and then, finally, we can add solar to fleet, given the right kind of call from the AESO.

So, converting the coal plants to gas either now—now being sort of that 2020 timeframe—or in 2030,

will depend on our—we very much believe will depend on our ability to work collaboratively not only

with the provincial governments, but also with the federal government, because we do need to have a

framework that allows us to understand—that has certainty and clarity on emission standards and

carbon pricing as we go forward. That framework has to protect new investments and maintain the

economic viability of our current plants. We know that our plants are needed for at least the next 15 to

20 years. So, we all know that Alberta is going to a 30% renewables standard by 2030. There is no

way, in Alberta, to add renewables to the system without having several plants like ours to back them

up. So, Alberta must have several plants to provide low-cost base load and backup power to ensure

system reliability and to ensure the kind of pricing we need that will undermine our resilient economy. If

we’re going to continue operating these plants, our investors must see that new rules and regulations

will allow for recovery of, and a return on, their capital.

Now, electricity and energy have always been at the heart of the economy here in Alberta, and we

know that any changes must support our communities at a time where, frankly, jobs are critical to the

province’s families. As such, we believe that governments have a strong incentive to work with us to

ensure that a transition away from coal in this province is carefully managed.


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So, in our view, the Alberta coal fleet offers a unique transition opportunity. Why? Coal to gas

conversions are low cost, these investments are only about 10% of the total cost of new combined

cycle plants, and additionally, the investment return horizon for a converted unit is only 10 years to 20

years—this is far shorter than the 30 years to 40 years required to recover investments in new

combined cycle gas plants—and since carbon-based electricity will grow increasingly uncompetitive,

using a shorter timeframe, is the prudent choice to make for our investments.

We will continue to work towards the goal of achieving fair compensation for our stranded Alberta

assets, but now we’ve had to add a second goal for our team. We must work with the provincial and

the federal government to create a certain regulatory framework that supports investments in carbon

fuel plants as backup from renewables. Transitions, as you know, are never easy, and navigating a

successful energy transition in Alberta and across Canada is both necessary and required.

Now, we believe the standard by which to measure a successful transition is grounded in our theme of

“balance wins”. The decisions we make must come from balancing the needs of our diverse operating

stakeholders, and I’ve said before that we know what these needs are. Our customers are clear that

they want reliable and affordable power, our investors want to be assured that their capital is safe and

they’ll earn fair, competitive returns on any investments, whether they be in renewables or they be in

gas or future investments in our coal plants, and of course, our citizens and government want clean and

cleaner energy and a strong sustainable economy.

Now, we believe that these views were echoed by Premier Notley’s comments made during her State of

the Province address a few weeks ago. In particular, her statements on the Climate Leadership Plan

were as follows: She said that “we will be spelling on a framework for a conversion later this fall,” and

then she also went on to say that, “as part of the government’s plans, they will set out a program to

provide coal emitters with some of the capital they need to close their plants and to invest in cleaner

power production, as coal is phased out in Alberta.” They also said that they “will set out how

proponents will be able to bid in Alberta’s market to help replace that coal-powered generation”, and I

think that news came earlier this week, as people talked about some of new roles that are emerging for

the renewables call that will come. Then, finally, they said that they “will set out more details on how

they will promote the construction of clean renewable energy, wind, solar, thermal, which of course

includes gas, and hydro power, efficiently, economically and without undue subsidies.”


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So, based on those comments, we were pleased with the general direction being taken by the

government, including the development of a framework and the provision of capital for converting some

coal to cleaner forms of power production.

We’ve all said that we recognize the need for change and the importance of making decisions that work

for today and tomorrow, and of course, in 2000, when the Alberta system was transitioned from a

regulated to a market-based electricity system, we did learn an important lesson there, as well, and that

is that balance always wins.

So, in closing, the key takeaways from the call today are this. First, the first three quarters in 2016,

we’ve had solid financial and operational performance, and we’ve leveraged the Company’s execution

advantage very well—and I really want to thank all the employees that have just done an amazing work

and continue to do so as we go forward into 2017; second, we’re progressing on all of our 2016 goals

and we don’t see any place where we’d have change—where we won’t deliver a goal; and then, finally,

transitioning the Alberta system off coal will require us to complete a fair compensation agreement—

sorry, a fair coal compensation agreement with the provincial government. We will also require much

greater certainty on the future path of carbon taxes and emission standards for carbon-based plants to

support the system. We will make sure that before we invest your money in carbon-based electricity

here in Alberta, we will have a way to recover that capital with a return.

So, with that, I’ll return the call over to Jaeson for questions.

JAESON JAMAN:

Thank you, Dawn. Zubin, we’re now ready to move to the Q&A portion of today’s call.

OPERATOR:

Thank you. Ladies and gentlemen, we will now begin the analyst question-and-answer session. Any

analyst who wishes to ask a question may press star, and one on their touchtone telephone. You will

hear a tone acknowledging your request. Please ensure you lift the handset if you are using a

speakerphone before pressing any keys. If you wish to remove yourself from the question queue, you


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may press star, then two. Any analyst who has a question may press star, and one at this time. There

will be a brief pause while we compile the question-and-answer roster.

Thank you. Our first question comes from Rob Hope from Scotiabank. Please go ahead.

ROB HOPE:

Yes, good morning. I was hoping you could comment on, I guess, capital allocation and how you think

you will be competitive in the new renewable procurement framework.

DAWN FARRELL:

I’ll talk about how we’ll be competitive and then maybe you can just give me a little more on what you’re

looking for on capital allocation.

As you know, we have TransAlta Renewables. It’s a very, very strong currency in the marketplace

today, and it’s got great capacity to add projects in it, just given its current capital structure. In Alberta,

we have existing wind farms that are close to transmission and would be very, very competitive in terms

of expansion. So, when we put those two things together, we believe we’re one of the top competitors

here for any of those projects that will be bid on in the upcoming call.

Can you just explain what you’re thinking about in terms of capital allocation?

ROB HOPE:

Maybe I’ll just frame it this way, or I’ll maybe go into a bit of a different direction. Just in your

comments, you did mention if you were going to invest capital, you’d have a clearer line of sight on a

return on and of capital. Does this allude to the fact that you will not be investing on a merchant basis

and that you’d be looking for contracts for any capital?

DAWN FARRELL:

Yes.

ROB HOPE:

All right, that’s helpful. Thank you.


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DAWN FARRELL:

Yes.

OPERATOR:

Our next question comes from Linda Ezergailis from TD Securities. Please go ahead.

LINDA EZERGAILIS:

Thank you. Just a follow-on question with respect to some of the changes that we’re starting to see in

the Alberta market. I’m wondering what sort of effect this most recent announcement on the renewable

procurement process might have on the merchant markets and your legacy assets, and at what point,

in terms of these changes, might you look to the government to provide certainty not just on new

investments, but on your legacy investments with a return on and of capital, potentially, type more fixed

contracts.

DAWN FARRELL:

Yes, I think, Linda, that hopefully—that’s really what I was trying to say in my comments. I think, as you

know and I know, as we go forward, as more renewables come into the system, they have to be backed

up with capacity, from thermal in the short to medium-term, and maybe over the longer term you might

see battery storage or things like that, or even storage from our hydro facilities, but in the short-term it’s

going to be backed up by thermal. In order for us to make investments in those thermal plants, we

have to be able to get our capital back out. So, I do think, as we move forward here in Alberta—as you

know, we’ve got time, the market is fine here in the next couple of years, but as we move forward, we

have to some way of ensuring that investments that we make to backup the system are recoverable

with the returns.

LINDA EZERGAILIS:

Okay, and just further beyond your thermal, for your wind assets, what might happen to pricing? How

correlated do you think the wind resource might be in the province to maybe put additional downward

pressure on pricing when your wind plants are actually generating, and do you think the government

might compensate you for that, if all this new power is coming on on the wind side?


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DAWN FARRELL:

Well, I think the government have a stated objective of getting to 30% renewables. To do that, I mean,

it’s a combination of new and old, right? Alberta already has a significant number of renewables in the

system. I think, again, as the market is evolving in order to go through this transition, I can’t see an

outcome where you effectively hurt the old fleet in order to bring in the new fleet. So, I do think there

will be significant discussions with the AESO and the government on how to ensure that incumbent

assets are not disadvantaged in this transition, and that includes our wind assets.

LINDA EZERGAILIS:

Great. Thank you.

OPERATOR:

The next question comes from Jeremy Rosenfield from Industrial Alliance Securities. Please go ahead.

JEREMY ROSENFIELD:

Yes, thanks. I have few questions here. Just to be clear—and let’s go back on the coal compensation

issue—the government has not indicated to you at this point in which direction exactly it would like to go

and you’re still expecting to see something from the government by the end of this year.

DAWN FARRELL:

So, we have said all year that we thought it would take about a year to do this work. I can’t comment

on just kind of what the discussions have been, but I can give you—I am pretty confident that we will

have something done on that by the end of the year.

JEREMY ROSENFIELD:

Okay. There’s a little bit of a disconnect that I’m seeing, I’m trying to understand. You still believe that

the market structure itself will not change, even though, inherently, obviously, the contracts for

renewables will be there, but do you think there could also be some kind of contract put into place from

the government to support some of the existing thermal capacity, as well?

DAWN FARRELL:


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Listen, I don’t think I’ve ever said that I don’t think the market structure will change here in Alberta. I

think I’ve been pretty clear that I think it has to change as we go through this transition. I do not see a

way through with the existing market structure staying the same. So, I believe the market structure will

change. I think the market structure has to figure out how bring in renewables with a reasonable

amount of subsidies, it has to account for all the incumbent assets that are here today, and has to

assure that any of the assets that backup the system from renewables are profitable. So, I don’t expect

the market structure to stay the same.

JEREMY ROSENFIELD:

Okay, and then let me just clarify one other point in terms of how TransAlta and TransAlta Renewables

would be approaching the new procurement process for renewable capacity. The goal is still I think,

and correct me if I’m wrong, to have TransAlta Corp. do the development, be the developer of the

assets, but ultimately, once an asset reaches sort of a de-risk state, to potentially have TransAlta

Renewables become the owner of that asset or become the holder of the economic interest in that

asset.

DAWN FARRELL:

Yes, that’s correct. We haven’t changed any of our views on that.

DONALD TREMBLAY:

Keep in mind, clearly, building wind projects in Alberta in a market that we know, on site, that we know

very well, it’s probably not as risky as other forms of development.

JEREMY ROSENFIELD:

Okay, perfect, great. That’s it for the moment. Thanks.

OPERATOR:

The next question comes from David Castagna from Raymond James. Please go ahead.

DAVID CASTAGNA:

Thanks. Hi everyone. I just have one question, just kind of a higher level strategic one. How do you

think about the potential—I would certainly agree that you are well positioned to go ahead with


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renewables in Alberta, but I guess, depending on how heavy the competition ends up being there, how

do you weigh expansion there as opposed to potential further expansion in Australia, and do you still

consider the U.S. wind market as something where you would consider expanding?

DAWN FARRELL:

Yes. So, going back to this sort of concept capital allocation, any of the assets that we’d look at in

Alberta would be held up against other projects that we are looking at in our portfolio. We’re not going

to just build in Alberta for the sake of building in Alberta. We do, though, have some pretty significant

competitive advantages in Alberta, just given the wind farms that we already have, the expansion

capabilities we have, our knowledge of the regulatory market, and our ability to understand what pricing

will look like in the future, because we have such a big future. So, I think that the Alberta assets will

compete favourably, but we continue to hold them up against returns that we see in other markets, and

if the returns are better in other markets, we would be going there.

DAVID CASTAGNA:

Okay, great, thank you, and just one other question, a pretty short one, I think. I know the PPAs for the

hydro assets in Alberta come up in 2020. Would you re-contract those prior to the expiration, or would

that be something that happens once they expire?

DAWN FARRELL:

You know, that’s a really good question, a strategic question. I mean, it really depends on what the

market structure looks like and sort of what the price signals are for different forms of capacity and

ancillary services. We are open to either keeping those uncontracted, because, frankly, they’re more

valuable today uncontracted than they are under the current PPA, but to the extent that there is a good

contract extension, we’d certainly talk to the AESO about extending those.

DAVID CASTAGNA:

Okay, great, thank you. That’s all I had.

OPERATOR:

The next question comes from Andrew Kuske from Credit Suisse. Please go ahead.


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ANDREW KUSKE:

Thank you. Good morning. I guess the question focuses on Alberta, and it’s just how are you

approaching just a simple supply-demand modeling analysis of the market, just given the uncertainty

that exists? I mean, obviously, this is straightforward, you can still do the supply/demand, but when you

look out into the future, just because of the government uncertainty, how do you factor that into your

analytics?

DAWN FARRELL:

Well, Andrew, you know that my background is economics, so this is like kind of the funnest thing we’ve

ever done at TransAlta, for me. My team is all cringing. So, we model the market 20 different ways.

We have modeled in the current market structure. We model as if there could be a capacity market.

We’re modeling CFD markets. We’re making up all sorts of ways that you could do the market here, all

looking at how do you ensure that you get the right investment returns to attract capital and then how

do you ensure that customers at the end of the day pay the lowest price. We’re really committed to an

Alberta market that delivers at the lowest price in a future where carbon is going to priced. We’ve

moved away from just modeling using the energy-only market to a lot of scenario analysis, so that really

helps inform our investment decision-making.

ANDREW KUSKE:

Okay, that’s helpful. Then, when you take a look at your scenario analysis, what really winds up being

your preferred outcomes in Alberta for TransAlta, and then how do you parallel that with other

jurisdictions where you either have capital in place or look to allocate capital into the future?

DAWN FARRELL:

Yes, I always come back to a general principle, which is that the services that are being provided by the

generators need to be priced, and so, to the extent that over time—not in the short-term, because you

know Alberta today is mostly provided by base load, supply is provided by base load coal—but over

time, as you feather more renewables into the system, all the generators are going to have to provide

more backup and more peaking and more capacity. So, a lot of market structures work, as long as they

give the right price signal to capacity so that capacity will be built to backup the system.

ANDREW KUSKE:


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Very helpful. Thank you.

OPERATOR:

The next question comes from Robert Kwan from RBC Capital Markets. Please go ahead.

ROBERT KWAN:

Good morning. Dawn, I guess, as you were talking about all the different things that the government’s

put out around what they could be announcing by year end, I’m just wondering, is it your expectation

that what they will announce will be really kind of a final framework, or do you expect them to put

forward a framework for further consultation?

DAWN FARRELL:

Oh, I think it’s next to impossible for any governments to put forward a final framework that would give a

lot of certainty, but I do think that they would give good signals in terms of the kind of framework that

they’re testing, and then I do think there will be a lot of consultation and a lot of discussion here in

Alberta over the next year, or even two. So, I think it’s—again, I want to reiterate, we have PPAs.

You’ve seen the performance of the company. We really make sure that we solidify the amount of

money that we can make here in the market while we’re under the PPAs and while we have the current

market structure. So, we’re fine with that, we think that’s the right thing to do. I personally believe, and

I’ve said this before, you’ve got to take a lot of time here if you want to have a really good marketplace.

I was just in Germany last week. I can tell you they have blown up every market worldwide by not really

considering the implications of the transitions towards renewables.

So, I think the framework will be there, but the kind of discussion that will make the framework work will

take some time.

ROBERT KWAN:

Okay, that’s great, and if I can just turn to the Alberta coal fleet—and I have a few fairly small questions.

You’ve nudged down availability for the year. I’m just wondering what’s behind that. We’ve seen a lot

of units kind of coming on and off line, and if you can just add some colour as to what the driver is and

whether that’s ongoing.


17

DAWN FARRELL:

Yes, I think—well, they had—we had a big flood in the mine, right? There was a one in 1000-year

rainstorm up in Edmonton. So, they’ve been struggling on two fronts. One is just struggling with getting

that mine, so they can get production out of it. They have the right amount of production, but there’s a

lot of work that they’ve been doing there. As a result of that, we’re using a lot of coal out of pile. The

coal in the pile is—well, it’s been in the pile for long time, so they’re ending up with quite a bit of a

capacity issue. So, I think it’s really just trying to get through that event and back to more of a normal

period, and of course, as you know, Sundance Units, we’re not maintaining those plants any more than

we have to, under the terms of the PPA, because of the life of those plants. So, we’d expect to see a

different kind of availability going forward with some of those older plants.

ROBERT KWAN:

Got it. Actually, Dawn, since you mentioned kind of the coal in the mine and floods, maybe I’ll transition

the second question there. You’re looking at coal costs, I think, in Alberta actually going down a little bit

more than what you’d previously guided. So, with the weather and the lower availability, usually that’s

bad for standard costing, so I’m just kind of wondering what’s the driver there. Are you going to really

ramp up inventory in Q4 to amortize it all?

DAWN FARRELL:

Well, Donald said in his—we’ve stated the Coal Team is working on a production plan for Q4, so that

they can keep the standard costs lower, so we’ll see how they do. They certainly have a pretty good

plan, but there is some risk in that, for sure, as they go through Q4.

ROBERT KWAN:

But, Dawn, is the plan largely centred around just building a bunch of inventory to kind of amortize the

fixed costs over that amount of production?

DONALD TREMBLAY:

We have a mine plan that basically is over multiple years, Robert, and we have some equipment,

planned equipment maintenance next year, so we’re also building like some inventory so we can go


18

over that period, as well. So, it’s not basically building inventory to reduce the standard costs. It’s

basically like a long-term mining plan that we’re trying to stick with at this point.

ROBERT KWAN:

Got it, okay, and then just the last question I’ve got. There’s been all this talk around all the carbon

plans, whether it’s federally or provincially. I’m actually just wondering, is CASA still an issue?

DAWN FARRELL:

Yes, I don’t think I’ve thought about it for about six months. No, I don’t think so. I mean, the reality is

that it just would make zero sense to put any capital investments into coal plants. So, as we’ve been

building our scenarios here, certainly all of our scenarios are to use existing credits that we’ve built up,

as opposed to put new equipment into the plants.

ROBERT KWAN:

Okay, I understand the first part and the use of the credits, but I think there was also a physical

compliance rule at some point?

DAWN FARRELL:

Yes, that’s what I’m saying, but that requires capital, so …

ROBERT KWAN:

So, it doesn’t make sense—sorry, go ahead, Dawn.

DAWN FARRELL:

Yes, so it doesn’t make sense to put in cap expenditure. Many of our scenarios are trying to figure out

how to optimize the portfolio and not have to spend that money.

ROBERT KWAN:

Got it. So, by optimize, you’re talking about essentially just having to shut stuff down earlier then?

DAWN FARRELL:


19

No, there’s lots of options, which I talked about in my speech. We can convert our products to gas, we

can always shut down plants and we can keep them running on coal, so we have a number of

scenarios that have a number of different outcomes in them.

ROBERT KWAN:

Got it. Again, that’s very helpful.

DAWN FARRELL:

It all depends on how solid and certain the framework is, as we go forward.

ROBERT KWAN:

Okay, that’s great. Thank you very much.

OPERATOR:

The next question comes from Robert Catellier from CIBC World Markets. Please go ahead.

ROBERT CATELLIER:

Hi, good morning. I was wondering if, just on Alberta, restructuring the market there, you’ve said you’ve

done a lot of modeling, etc., and looked at it a lot of different ways, but do you think there’s one sort of

restructuring framework that best suits TransAlta’s assets?

DAWN FARRELL:

No. Actually, we’ve been surprised. When you do the actual detailed modeling, there are a number of

different structures that will work, and again, remember, the criteria we’ve put in front of ourselves is

keeping prices low for consumers, ensuring that the assets in not just TransAlta’s suite but the other

incumbents as well here in the province, get returns, and then also the shift to renewables. So, I’ve

been surprised, actually, at the number of different ways that you can do it, and I think, going back to an

earlier question about a framework versus a very detailed assessment of which way to go, I think as

long as the framework recognizes that thermal backup has to earn a return to provide the capacity for

the system, and it also recognizes that over time—I do believe that over time carbon-based fuels are

going to be used less and less and there’ll be more in addition. As long as the framework has those

attributes in it, I think there’s a number of frameworks that work. I don’t have any one that I would say,


20

oh, we’ve got to go here or we’ve got to go there. I’m just pretty sure that the one that we have today is

not going to work.

ROBERT CATELLIER:

Okay. So, just thinking out loud here, you know, there’s obviously conflict between wanting to keep

prices low and reducing the exposure the government has under contracts for differences. Do you think

they have to change the rules on how renewables can bid into the market under a revised market

structure? In other words, you can’t create an incentive where they push the stack down and the

government ends up with a huge bill for the contract for differences, like we’ve seen in Ontario.

DAWN FARRELL:

Yes, I mean, those are all things that have to be considered in the dialogue as we go forward.

ROBERT CATELLIER:

Do you get any sense that that’s a major part of the dialogue, that they’ll actually get to a position where

the renewables can’t be bid in, disadvantaged in a way that disadvantages the existing fleet, whether

it’s coal or renewables?

DAWN FARRELL:

You know, I mean, it would take a long time to have that discussion here on this call. I can honestly say

I don’t know how that will come out, but I do think that—I think there’s good recognition of all the

stakeholders here in the provinces, including the AESO, and the government, of what all the factors are

that need to be considered. So, going back to my comment on “balance wins,” all of this has to be

balanced as we go forward.

ROBERT CATELLIER:

Okay, I’ll try just one last time and then that’ll be it, but how can a contract-for-differences market work

without changing the way renewables bid in? Is it possible to achieve the objectives without changing

the way renewables bid in the market, in your opinion?

DAWN FARRELL:


21

I’ve seen two market structures—I’ve seen several market structures where contracts for differences

either changes the bidding behaviour or doesn’t, so I think there’s—I think it can work either way.

ROBERT CATELLIER:

Okay. Thank you.

OPERATOR:

The next question comes from Mitchell Moss from Lord Abbett. Please go ahead.

MITCHELL MOSS:

Hi, a couple of questions. You mentioned higher financing costs. Is that just financing costs related to

expected project level financing?

DONALD TREMBLAY:

Like, it’s a two-fold. So, we’re clearly, like, raising money ahead of time. So, we’re doing project

financing and putting cash in a bank account in anticipation of 2017 construction of South Hedland and

refinancing. We also had a little bit of, like, a step-up in our financing costs because of the Moody’s

downgrade last year, like marginal, but that also had a small impact on our financing costs this year, but

it’s mostly due to us basically raising cash ahead of time and having a negative carry on that cash

currently.

MITCHELL MOSS:

Okay, but the coupon on the project financing related to South Hedland isn’t necessarily higher, it’s just

that you did the financing sooner?

DONALD TREMBLAY:

Exactly. In fact, it would be a cheaper rate, but it’s just the timing of us raising the money now versus in

2017.

MITCHELL MOSS:

Okay. Regarding the comments around coal to gas conversion, how much—if the 2020 timeframe

were to play out as to a need for some of those facilities to run on gas, how much lead time would you


22

need, and what steps are you taking now to potentially have some plants be converted to gas in the

2020/2021 timeframe?

DAWN FARRELL:

Yes, I mean, the lead time is about now, right, and this is part of the work that we’re having to do here

in the province, just getting some clarity, because the more clarity we have, the more likely we can

make decisions that will get us there by 2020/2021. The biggest roadblock to that is a gas pipeline,

which would need about three years. So, that is the kind of work that has to done, if that was to be one

of the scenarios that we pursue.

MITCHELL MOSS:

Okay. So, the gas pipeline is three years, but in terms of the actual engineering of the fuel switch, do

you need to take significant steps now, as well?

DAWN FARRELL:

You know, that is actually not that big a deal. That can be done on an extended outage …

MITCHELL MOSS:

Okay.

DAWN FARRELL:

… and the engineering on that is not complex.

MITCHELL MOSS:

Great. Thank you very much.

OPERATOR:

The next question comes from Ben Pham from BMO Capital Markets. Please go ahead.

BEN PHAM:


23

Thanks. Good morning. On RNW, I was just wondering, the recent run-up in the stock, does that

perhaps (inaudible 48:08) of your decisions with dropdowns or perhaps selling down a portion your

interest?

DONALD TREMBLAY:

No. Like, it’s a clearly good, it’s a strong currency. So, if we decide to use, it’s available. But, no, it

doesn’t create an incentive for us to basically move forward with those strategies.

BEN PHAM:

Even dropdowns?

DONALD TREMBLAY:

We will likely do future dropdowns, but it will not be driven by the current stock price. We will do the

dropdown when it’s appropriate for TransAlta to do a dropdown, because we need to pull money from

RNW to TransAlta, but it’s not something that we’re contemplating at this point.

DAWN FARRELL:

I mean, in terms of priorities, currency is really—it really positions us well on the growth side.

BEN PHAM:

Is the hydro fleet still in that potential bucket of dropdowns for you guys?

DONALD TREMBLAY:

Like, it will be there, but as we discussed earlier, the contract is expiring in 2020. We don’t know what

will be the market in Alberta past 2020. So, as soon as we have more visibility on this, then we can

draw a better plan, but for now it’s very challenging to value that asset to drop it down into our RNW, so

that’s why, like, it’s kind of on hold for now.

BEN PHAM:

Okay. On the coal transition, can you comment on the potential outcomes on compensation, a

proposal that you or others may have put in front of Boston, and even leading up to a final decision

that’s coming out by year end?


24

DAWN FARRELL:

No, we cannot.

BEN PHAM:

Okay. Then, on the Canadian coal, there’s commentary about the curtailments from the PPA buyers.

Is that referring to the balancing pool there, basically, instead of buying cheap spot there, still

dispatching and paying a higher PPA contract price?

DONALD TREMBLAY:

That’s exactly the case. Normally, when prices are low, we see the PPA buyer taking the unit off line,

or part of the unit off line. The balance pool currently is dispatching their unit at basically marginal

costs. The units are running more than quite what we’re expecting in that low price environment, and

that’s a bit of a negative for us.

BEN PHAM:

Okay. Then, just to clarify, the hydro, you talked about some water management flexibility. I just want

to refresh my knowledge. I thought most of them were—most of your fleets, they run upriver. Is there

some reconfiguration or is that some other asset that’s driving that?

DAWN FARRELL:

They run upriver, but we also have storage and we use that storage all the time. In fact, that’s why we

have good capacity out of those facilities.

DONALD TREMBLAY:

The North Saskatchewan system has significant storage at Brazeau and Bighorn. That’s what we think.

BEN PHAM:

Okay. All right, great. Thanks for taking my questions.

OPERATOR:

The next question comes from Rob Hope from Scotiabank. Please go ahead.


25

ROB HOPE:

Yes, thank you for taking another follow-up. Maybe moving over to Washington, do you have any

comments on the State Ballot initiative that could see additional carbon costs be put on Centralia?

DAWN FARRELL:

No. We’re just like you, we’re just in wait-and-see-what-happens-there mode.

ROB HOPE:

So, your existing framework, where you’re shutting down the units, wouldn’t add some sort of shield to

this potential?

JOHN KOUSINIORIS:

As Dawn said—it’s John Kousinioris—we are watching the matter closely, we’re waiting to see what the

outcome of the vote is going to be next week, and we’re looking at what the potential implications are,

but we’re not in the position right now where we can speculate, to be honest.

ROB HOPE:

Great, that’s helpful. Thank you.

OPERATOR:

This concludes the analyst question-and-answer portion of today’s call. We will now take questions

from members of the media. As a reminder, please press star, and one on your touchtone phone to

ask a question. If you wish to remove yourself from the question queue, please press star, and two.

The first media question comes from Jeff Lewis from The Globe and Mail. Please go ahead.

JEFF LEWIS:

Hi, thanks for taking my question. Dawn, can you just clarify what it is that you’d like to see from the

Alberta government, and perhaps the federal government, in terms of assurances, as you look to

transition the coal fleet to perhaps gas peaking plants, in terms of, I guess, just financial assurances.


26

You mentioned a couple times you need to see a return profile that make sense and allows you to get

your capital back. Then, I have a follow-up. Thanks.

DAWN FARRELL:

Okay. I’ll start and then I’m going to ask John to—because he’s been working on this pretty

extensively. So, first of all, in order to run our units on gas, we do need a regulatory framework over a

longer period of time, sort of in that 15-year timeframe for our sub-critical plants and 25 for our super-

critical plants, because, as you know, they’re brand new. So, we do need a performance standard. We

need to know that we have the right performance standard that we can operate those plants within, and

that’s in the jurisdiction of the federal government for that.

We also believe that to make those investments—to make investments in carbon-based fuels, just

given the uncertainty about where carbon tax could go, that we need to be able to get some sort of

assurances on what the carbon taxes will be over the timeframe of the investment. As you can

imagine, anybody investing in new thermal plants, electricity plants that have carbon in them, in this

environment, really has to know whether or not in the future there would be an upset in their returns

because of a carbon tax, and particularly people, like ourselves, would want some of those assurances.

So, we need that, as well, as part of what we’re doing.

Is there anything else? I think it’s really those two key things, but I will let John add some comments.

JOHN KOUSINIORIS:

Yes, I don’t—I think Dawn covered it well. I think the two things that she said would be, one, making

sure that the emission standards that would be set by the federal government and the provincial

government would be appropriate to permit the conversion of the coal units to gas units. There are

significant emissions reductions by doing. The emissions actually go down by almost half, in terms of

greenhouse gas emissions. So, that’s one. The other one, as Dawn alluded to, would be it would be

helpful to us to understand kind of the forward trajectory of what carbon pricing might be and what the

performance standard would be, so we have a bit of a sense of what the economics would be for the

units that we would be considering to do the conversion. So, it’s really the two elements are really

oriented towards giving us elements of certainty to permit us to move forward.


27

JEFF LEWIS:

Do you mean prices beyond the $50 per tonne that’s been outlined in the federal government plan?

JOHN KOUSINIORIS:

Yes.

DAWN FARRELL:

Yes, because, remember, these are long—even though these are more like 15-year investments

instead 30-year on a combined cycle, they’re still 15 years to recover the capital for investors, so they

need a pass in order to make that investment, or they need some certainty on that. They can’t—the

risk is too big because the input cost is too high as a percentage of all the input per cost.

JOHN KOUSINIORIS:

For, example, if you do a conversion in 2020 or ’21, as Dawn alluded to, and the carbon price is

scheduled to go under the federal rules to $50 in 2022, there’s still 15 years or so that you would need

to run. So, having a bit of a sense of what pricing would be as an input cost on a go-forward basis is an

important consideration for us.

JEFF LEWIS:

Okay. Then, secondly, just on the renewable announcement that was made yesterday by the Alberta

government, are those financial incentives enough for you to consider new capacity?

DAWN FARRELL:

Yes.

JEFF LEWIS:

Okay. So, you’re pleased with those?

DAWN FARRELL:

I think we predicted that that was the way you’d have to go in order get investors behind those kinds of

projects. So, I think, to the extent that—you know, I think that those kinds of instruments will create the

most competition, the lowest cost to capital, and potentially the lowest subsidy on renewables.


28

JEFF LEWIS:

Okay. Thanks.

OPERATOR:

As a reminder for the media, please press star, and one on your touchtone to ask a question.

The next question comes from Chris Varcoe from the Calgary Herald. Please go ahead.

CHRIS VARCOE:

Hi, thanks for taking my call. Dawn, potentially, how many of your existing coal plants are you looking

at the potential for conversion to gas, and what would you expect the range of these capital costs to

be?

DAWN FARRELL:

Well, just to qualify, remember, we need the right framework to do it, so the right regulatory framework,

and certainty and clarity in that, to be able to do that, but we’re running scenarios that would have all of

them, some them, one or two of them. So, it really depends on what the market looks like here and

what the incentives are for—incenting us to provide capacity to the system. At this point, we wouldn’t

have an answer to that. We’re just running different scenarios as we think about what’s going on in this

environment.

In terms of the costs, they’re not a very expensive endeavour. It’s about $125 a kilowatt a year for a

coal conversion, compared to, let’s say, a brand new combined cycle plant can be somewhere

between—anywhere between $1,500 to $2,000 in the Alberta market, depending on when you’re doing

the construction. So, it’s a very—it’s one-tenth the costs.

CHRIS VARCOE:

Just to follow up on the question about the renewables, given that the government’s going to be

bringing in these new renewable contracts as contracts for differences, will you be seeking the same

kind of subsidies, the same kind of contract for differences for the existing renewables that you have in

the province?


29

DAWN FARRELL:

Yes, you know, we just got that information yesterday. For sure, the existing renewables cannot be

disadvantage by new renewables being brought into the province. There’ll be lots of discussions on

how to do that. There is currently renewable credits that go to the existing projects, so I think, to the

extent that they continue, that can service that, but there’s lots of work to do before we get any real

certainty or clarity around that.

CHRIS VARCOE:

Thank you.

OPERATOR:

There are no more questions at this time and this concludes today’s conference call. You may now

disconnect your lines. I want to thank you everybody for participating and have a pleasant day.

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